Just some important information to keep in mind when talking about the eventual decline and fall of the mighty Bakken.

The estimate of original oil in place for the Bakken most quoted was that done by Leigh Price who estimated a mean OOIP of 413 billion bbls.

The USGS has estimated the amount of technically recoverable oil from the Bakken has a mean estimate of 7.4 billion bbls. That would be an ultimate recovery factor of ~1.8%

From 2008 through 2013 it is estimated that 450 million bbls had been produced from the Bakken. Given the average daily production from the Bakken there would have been an additional 1.7 billion bbls produced through to 2018. A reasonable estimate of total produced to date would thus be around 2.2 billion bbls.

What that means is that even if ultimate recovery factor is as low as what the USGS estimated (1.8%) then there is still 5.2 billion bbls yet to be produced or a little over double current production.

That being said a few years after the USGS estimate it was noted that average wells were producing at double the rate in the first year suggesting well EUR would be higher and that ultimate recovery factor would also be higher.

In 2011 a paper published in the SPE

Dechongkit, P and Prasad, 2011, M. Recovery Factor and Reserves Estimation in the Bakken Petroleum System (Analysis of the Antelope, Sanish and Parshall fields), SPE 149471

Noted mean recovery factors for the Bakken anywhere from 9% to 16%.

If we were to assume ultimate recovery factor of 6% (well below the lowest estimate of Dechongkit and Prasad, 2011) that still leaves over 20 billion bbls of oil to be produced. That number is interestingly at the low end of the estimate of ultimately recoverable reserves from the Bakken made by Continental Resources of between 20 and 40 billion bbls.

rockdoc123 wrote:If we were to assume ultimate recovery factor of 6% (well below the lowest estimate of Dechongkit and Prasad, 2011) that still leaves over 20 billion bbls of oil to be produced. That number is interestingly at the low end of the estimate of ultimately recoverable reserves from the Bakken made by Continental Resources of between 20 and 40 billion bbls.

This suggests that by all accounts the Bakken is nowhere near dead.

Thanks for the data.

Despite the history that shows improving efficiency and processes in complex processes are common, if not the norm, that's something Cassandras absolutely DO NOT want to hear, much less incorporate into their forecasts of short term doom.

Given the track record of the perma-doomer blogs, I wouldn't bet a fast crash doomer's money on their predictions.

ROCKMAN wrote:A "red flag" warning in the Bakken? No, it isn't: it's a condition fully anticipated by anyone knowledgable of oil production operations. This same phenomenon has happened in every newly developed trend of water drive oil reservoirs. Early on most of the wells produce no or very little water. But as a trend continues to be developed wells drilled early on begin producing more water as they deplete. But new wells are producing more oil. But eventually the NUMBER of the older wells (with ever increasing water production) begin exceeding the number of new wells brought on line. And simple arithmetic explains why the total water production in the trend starts exceeding the total oil production. It is inevitable and always has been. And this differential can show a very big jump should the number of new wells deceases significantly. As might happen if oil prices fall and activity decreases.

You are omitting the show stopper detail about the time of arrival of higher water cuts. The Bakken is evolving on a timescale noticeably shorter than conventional plays of substance. So at the end of the day, it ends up being a side show with lots of hype that made sound like some 2nd coming of the oil production of the 1960s. The estimates for the peaking of the Bakken in the next 10 years are looking more and more realistic. And the cherry on top will be the faster decline post-peak.

That's good news for anyone waiting for off-shore to come back. Since there would need to be a lead up, maybe that's five to seven years? I don't mean off-shore in the sense of developing things for large Middle Eastern players, like off-shore gas fields everyone already knows about, but in terms of wide scale exploration. The oil doesn't have to be there for that to take place, just the need to find it.

The question under consideration is not whether or not the Bakken is dead, but whether or not it the Bakken is nearing its peak level of oil production.

Since the best and most productive acreage mostly gets drilled first, it becomes harder and harder to grow production as time goes by and the best acreage is used up. One of the clearest signs that new wells aren't as productive as wells were in the past is the increasing amount of water (i.e. the water cut) in wells now versus wells drilled in the past.

Since the best and most productive acreage mostly gets drilled first, it becomes harder and harder to grow production as time goes by and the best acreage is used up. One of the clearest signs that new wells aren't as productive as wells were in the past is the increasing amount of water (i.e. the water cut) in wells now versus wells drilled in the past.

Shale production is nothing like conventional production. Although there are "sweet spots" in the shales that are often drilled earlier than later advancing technology and cost cutting (which have steadily been happening in the Bakken and other unconventionals) continually expands the area of economically attractive resource. As well the ability to downspace is still very high in the unconventionals given a maximum frack will penetrate no more than 100 - 150 m from the well bore. As to water, first (as was pointed out above by both coffee and me) the water being seen is almost certainly refrack water that wasn't previously recovered, in some cases intentionally. Since 2006 the volume of fracking fluid used per well has nearly tripled, meaning you should expect water production to increase. As well the Bakken is a gas depletion drive, it does not have an active water drive meaning the only natural water produce would be that not bound in pore space which is generally low in almost all shales.

Increasing percentages of water and less oil in productions wells has always been a bad thing in the oil biz. Don't let anyone tell you different.

well I think those of use who have dealt with many fields over the years would argue this isn't the case at all. As Rockman has pointed out there are many fields that start out producing high volumes of water and many fields that have been producing for many years at water cuts in excess of 90%. All that is required is a means of disposing of the water and economics that allow for that. And in the case of shales the means of disposing of refrack water is to reuse it in subsequent fracks.

P – “Increasing percentages of water and less oil in productions wells has always been a bad thing in the oil biz. Don't let anyone tell you different.” I’m not going to tell you different but will take the liberty to qualify you statement. You need to make sure you know what group of wells you’re referring to. Group A are wells drilled in the past and Group B are recently drilled wells. The A’s will be increasing in water cut as well as producing less oil. This is as predictable as the sun rising tomorrow: it has happened in every water drive reservoir ever developed.

The B’s OTHO are not as predictable. I can show you trends, such as the Frio of the Texas coastal plane, where wells drilled 30 or 40 years after it began being developed were still producing oil at the same initial rate and zero water cut as wells drilled in the 1940’s.

But here’s the tricky part: the fields developed in the 1940’s and 50’s ultimately produced 30 to 150 MILLION bbls of oil. But those recently developed fields will only cumulatively produce 30 to 150 THOUSAND bbls of oil. The timing of the development does not change the reservoir dynamics of production. Even worse: technology changes can have a very dramatic effect on that dynamic: look at the difference between the early VERTICAL Bakken wells and the more recent HORIZONTAL WELLS. In addition to much higher initial flow rates the horizontal wells will see water cuts and rate reduction occur much faster then the vertical wells. Even the more recent horizontal wells can have a significantly different production profile then earlier horizontal wells.

This can truly be a risk of comparing apples to oranges. In fact, even worse: apples vs oranges vs bananas vs watermelons. As a reservoir engineer the Rockman has spent 4 decades dealing with this phenomenon. You may be aware of these distinctions. Just wanted to keep any less informed on the right track.

The situation has changed drastically -- mainly because of new technologies and the free market. President Donald Trump has just announced the official end of the oil crisis. He also hinted at the end of the miles-per-gallon [MPG] restrictions on cars and trucks.

Yes Newfie: just another case of the blind (or ignorant) leading the masses of blind (or ignorant). You can't even take it for granted the POTUS (and his advisors) are that ignorant: they may just be taking advantage of a technical ignorant public to sell his agenda.

Where does the Constitution specify the role of government is to set mpg standards? I'll wait while you look it up. The market will set the price point at which consumers will either buy or find an alternative.